The present invention relates to a method and apparatus for determining the water conductivity of a multi-component mixture of gas and at least one liquid containing water in a pipe.
A flowing mixture of oil, water and gas or condensate, water and gas is a common occurrence in the oil industry being a product of an unprocessed well stream. Such a well stream is often referred to as a multiphase mixture where oil or condensate, water and gas are referred to as individual phases or fractions. When the amount of gas (GVF) is greater then 90% of the total volume in the pipe, the well is often referred to as a wetgas well. However, most wetgas wells have a GVF above 97% and it is common with GVFs in the range 99.7-99.9%.
The formation water in the hydrocarbon reservoir is typical saline water, and its salinity is usually known to the operator. Under normal situations, the well should not produce any formation water. In fact, formation water in the pipeline can cause hydrate and scale formation in addition to severe pipeline corrosion. If the amount of formation and fresh water (also referred as total water fraction) in a well is known to the field operator, chemical inhibitors can be injected into the well stream in order to limit the unwanted effects due to the water. Alternatively, the production rate from the well can be changed in order to minimize or reduce the formation water production or shut down the well completely to spare the pipeline infrastructure. It is of particular interest to measure the formation and fresh water content of remotely operated subsea wells since the cost of the pipelines in such an installation is severe. It is common for most subsea installations to commingle wells into a common pipeline and transporting the multiphase fluid to a process facility. Such a process facility may be located several hounded kilometers from the seabed installation leading to long multiphase transportation pipes on the seabed. Consequently, it may take many months to detect and identify a well producing saline water without an apparatus as described in the present invention installed at the wellhead on the seabed. If the saline water production of a remote subsea well is particularly high, it may even be necessary to shut down the well in order to avoid damage of the pipeline infrastructure. Knowing the total water (formation water plus fresh/condensed water) fraction and the water salinity, the fresh water and formation water fraction of the well can be determined since the salinity of the formation water is known to the operator. In order to fulfill the requirements of the field operator, an instrument for measuring at least the water conductivity/water salinity of the wells would be need. The water fraction can either be calculated based on a compositional analysis of the wet gas and using PVT (pressure volume temperature) correlations for calculation of the water fraction, alternatively the water fraction can be measured as described in one of the embodiment of this invention providing a more accurate determination of the water flow rate. In order to obtain safe and economical operation of the equipment at the seabed, the operator typical needs to know the salt content of the water fraction with a resolution in the range of 0.1%-0.5% NaCl by weight in the water fraction, and the water fraction of the wet gas with a resolution in the range 0.01-0.1% of the total volume of the pipe.
Many wetgas wells have a gas fraction (GVF) of 97-99.9% with a water fraction in the range 0.005-1%. However, there is also water present as vapor in the gas. For changing pressures and temperatures, some of the water vapor in the gas may be condensing to form liquid water. The mass of the vapor water in the pipe may be many times greater then the mass of the liquid water in the pipe. In addition the dielectric constant of vapor water is significantly higher (3-4 times) than the dielectric constant for the same mass of water as liquid phase. Consequently, the dielectric constant of a hydrocarbon mixture containing vapor water may be 10-20 times greater than the dielectric constant of a hydrocarbon mixture containing the same mass of water as liquid. Vapor water is of low importance to the operator since it does not influence scaling, waxing or corrosion of the pipelines to the same extent as saline water. However knowing the liquid water fraction and the salt content of the liquid water fraction is very important as outlined above, and hence vapor water adds to the challenge of measuring the liquid water fraction and water salinity since the ratio between the amount of water as liquid and amount of water as vapor also is pressure and temperature dependent. Consequently, small variations in the pressure and temperature, associated with changing flow rates or back pressure due to changing pressure drops in the transportation pipelines, can greatly influence the dielectric constant of the hydrocarbon mixture to a much greater extent than variations in the water fraction of the multiphase mixture. The dielectric constant of the gas is normally a calibration constant for instruments performing measurement of the water fraction of a wetgas. The dielectric constant of gas determines the zero point of the measurement of the water fraction. Hence, phase transition from liquid water to vapor water and vice versa influences the zero point of the water fraction measurement making reliable measurements at low water fractions even more difficult.
Microwaves are widely used for measurement of composition and water salinity of a multiphase mixture. U.S. Pat. No. 4,458,524 (1984) discloses a multiphase flow meter that measures the dielectric, density, temperature and pressure. Such device uses phase shift between two receiving antennas to determine the dielectric constant. Other techniques are further known being based on resonance frequency measurement. Examples of such techniques are disclosed in WO3/034051 and U.S. Pat. No. 6,466,035. U.S. Pat. No. 5,103,181 describe a method based on measurement of constructive and destructive interference patterns in the pipe.
However, none of the above described methods are able to measure both the water fraction and water salinity of a multiphase mixture, and all the devices above are highly influenced by any changes in the dielectric and density properties of the gas and oil.
It is also well known that the composition and dielectric loss (i.e. the complex dielectric constant) of a multiphase mixture can be measured based on measurement of resonance frequency and quality factor of a resonant cavity. The method disclosed in WO 03/012413 measures the composition and describes a method where the composition and dielectric loss of a multiphase mixture is derived based on measurement of resonance frequency and quality factor of two resonant devices placed at two different locations in a pipe. The two devices have different resonance frequencies. Hence the method relies on accurate power/loss measurement for a transmitted and received microwave signal. It is also well known that the complex dielectric constant of a media can be measured by measuring the phase shift and attenuation of an electromagnetic wave through the media. U.S. Pat. No. 5,793,216 describe a method and apparatus for characterization of a multiphase mixture based on transmission and reception of microwaves. The method is based on measurement of phase shift and power attenuation at several measurement frequencies. The antennas are located in the cross section of the pipe at several cross sections of the pipe. U.S. Pat. No. 4,902,961 describe a method for measuring complex dielectric constant based on measurement of phase shift and power attenuation. The measurement is performed at two different (fixed) frequencies, one in the X-band and the other in the S-band. Other examples can be found in NO 200 10 616 which discloses a method for measurement of the water conductivity of the continuous phase of a multiphase mixture based on a power and phase measurement at microwave frequencies, U.S. Pat. No. 5,341,100 describing a method and apparatus for measurement of fluid conductivity and hydrocarbon volume based on a measurement of phase shift and attenuation (power) of an electromagnetic wave and U.S. Pat. No. 5,107,219 describing a method and apparatus for measurement of the conductance of a fluid based on measurement of microwave energy (power/loss) and phase difference.
There are two main disadvantages with the above mentioned devices and methods. First, a change in the dielectric constant of the gas due to variations in the water vapor content or variations in the gas density influences the dielectric constant of the gas. As a consequence, the zero calibration point for the water fraction measurement is changing causing unacceptable measurement errors. Secondly, the above methods and apparatuses have limited ability to sense small variations and provide accurate and repeatable measurements since they rely on an accurate power or loss measurement at only one frequency or a few (two) fixed frequencies. Accurate power and loss measurements at microwave frequencies at one frequency or two fixed frequencies are difficult to perform partly due to impedance mismatch, which is very common for any microwave based industrial device for measuring dielectric constant, and partly due to limitations of the electronics itself. Consequently, the limitations of the measurement electronics and standing waves due to impedance mismatches make it difficult to obtain the required accuracy, repeatability and sensitivity for accurate water conductivity and/or water fraction measurements.
It is also well known that the composition of the multiphase mixture can be measured based on a measurement of the cut-off frequency of the pipe. Examples of such devices are found in U.S. Pat. Nos. 4,423,623, 5,455,516, 5,331,284, 6,614,238, 6,109,097 and 5,351,521 describing methods for determining the composition of a multiphase mixture based on a measurement of the cut-off frequency of a pipe based on loss or phase measurements at a varying frequency. NO 20043470 describes a method an apparatus for determining water salinity based on phase measurement(s) only. However, all these devices are highly influenced by changes in the dielectric constant of the gas due to variations in the water vapor content or variations in the gas density which both have a large influence on the dielectric constant of the gas. Devices based on measurement of conductance or resistance is also known for measurement of water conductivity and water fraction. However, these devices are highly affected by oil contamination isolating the measurement signal from the process since these measurements are normally performed at very low frequencies. Drift in the electronics due to temperature variations and aging is also a common problem with such devices. Consequently, such devices are not suited for high precision measurements of water conductivity and water fraction of a wet gas stream. All the above mentioned devices also require a flowing multiphase fluid in order to be able to perform the measurement. This means that the devices can not provide accurate measurement at stationary conditions in the pipe.
As mentioned above, all the previously mentioned devices require accurate information of gas and oil/condensate density and the dielectric constant of gas and oil (condensate). These data are a function of temperature and pressure and may also change significantly over the life of the well due to commingling of fluid from multiple production zones of a well. Multiple production zones means that the well produces from different layers in the ground and the composition of the hydrocarbon and water may be different for the various zones. In practice it is also quite often difficult to obtain accurate estimate of these calibration inputs, particularly for wells producing from multiple production zones in the ground.
Devices for measuring the flow rates of a multiphase fluid are well known. Such devices may be based on cross correlation of a measurement signal detecting variations in liquid and gas droplets of the flow. By transmitting a carrier into the flow and measuring the response, the received signal contain information of the variations in the flow caused by amplitude (loss), phase or frequency modulation by the disturbances (in-homogeneities) of the flow. By performing the measurements at two sections of the pipe located at a known distance, one can create two time varying signals that are shifted in time equal to the time it takes the multiphase flow to travel between the two sections. Example of such devices are disclosed in U.S. Pat. No. 4,402,230, U.S. Pat. No. 4,459,958, U.S. Pat. No. 4,201,083, U.S. Pat. No. 4,976,154, WO94/17373, U.S. Pat. No. 6,009,760 and U.S. Pat. No. 5,701,083
Other devises for measurement of flow rates may be based on measurement of differential pressures across a restriction in the pipe such as a venturi, orifice, v-cone or flow mixer. Examples of such devices can be found in U.S. Pat. Nos. 4,638,672, 4,974,452, 6,332,111, 6,335,959, 6,378,380, 6,755,086, 6,898,986, 6,993,979, 5,135,684, WO 00/45133 and WO03/034051.
It is the purpose of this invention to overcome the above mentioned limitations of existing solutions.
It is the purpose of this invention to perform accurate measurements of the salinity and/or conductivity of the water phase of a multiphase mixture containing small amounts of water.
It is the purpose of this invention to perform accurate measurements of the water salinity/water conductivity with a minimum of calibration parameters.
It is the purpose of the invention to provide accurate measurements of the water fraction of a multiphase mixture containing small amounts of water.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas with large variations in the dielectric properties of the gas.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas with large variations in the density of the gas.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas without the need for any flow through the apparatus.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas with large variations in the dielectric properties of the oil/condensate.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas with large variations in the density of the oil/condensate.
It is the purpose of this invention to perform accurate measurements of the conductivity of the water fraction of a wet gas at low water salinities.
It is the purpose of this invention to perform accurate measurements of the water salinity and water fraction and compensate the measurements for any variations in the dielectric or density properties of the gas.
It is the purpose of this invention to perform accurate measurements of the water salinity and water fraction and compensate the measurements for any variations in the dielectric or density properties of the oil/condensate.
It is the purpose of the invention to provide liquid hold-up in the apparatus such that the properties of the liquid phase can be measured more accurately.
It is the purpose of the invention to detect liquid hold-up in the apparatus.
It is the purpose of the invention to provide separation of the liquid and gas phases of a multiphase mixture such that more accurate measurements of the liquid phase can be obtained.
It is the purpose of the invention to provide a non-intrusive device for performing the measurements.
It is the purpose of the invention to provide a compact mechanical structure for performing the measurements.